The present disclosure is related in general to wellsite equipment such as oilfield surface equipment, downhole assemblies, and the like.
The statements made herein merely provide information related to the present disclosure and may not constitute prior art, and may describe some embodiments illustrating the invention. All references discussed herein, including patent and non-patent literatures, are incorporated by reference in their entirety into the current application.
Coiled tubing is a technology that has been expanding its range of application since its introduction to the oil industry in the 1960's. Its ability to pass through completion tubulars and the wide array of tools and technologies that can be used in conjunction with it make it a very versatile technology.
Typical coiled tubing apparatus includes surface pumping facilities, a coiled tubing string mounted on a reel, a method to convey the coiled tubing into and out of the wellbore, such as an injector head or the like, and surface control apparatus at the wellhead. Coiled tubing has been utilized for performing well treatment and/or well intervention operations including, but not limited to, hydraulic fracturing, matrix acidizing, milling, perforating, and the like.
Hydraulic fracturing, matrix acidizing and other types of injection operations are performed in oil and gas wells to enhance hydrocarbon production, or to reduce or seal unwanted production of water from certain zones. The wells being treated often consist of a large section of perforated casing or open borehole that has significant variation in rock petrophysical and mechanical properties. As a result of these different properties, a treatment fluid pumped into the well may not flow to all desired layers that need to receive the treatment fluid. Stimulation fluid may enter the most permeable layer (or uppermost layer) in the well and quickly remove formation damage and increase the injectivity, causing the remaining treatment fluid to go to the same layer while leaving other layers untreated. To achieve effective treatments, diverting agents, which can be chemical or particulate materials, may be used during the treatment to help reduce the flow into the more permeable layers that no longer need treatment fluid and increase the flow into the lower permeability layers. In addition, mechanical diversion devices, such as packers or the like, may be utilized to assist in diversion.
While the use of diverters may help improve flow distribution into multiple layers, there may be no assurance that the diverter will always be effective, nor may there be knowledge about how much of the target interval has been effectively treated while the treatment is being conducted. To ensure an effective treatment, a direct or indirect real-time downhole measurement of flow distribution is desirable to help the operator determine when and where to apply the diverters and by how much.
Traditional flow measurement in a well may be performed with production logging using a flow meter to measure the hydrocarbon production rate or injection rate in the wellbore as a function of depth. Based on the logged wellbore flow rate, the production from or injection into each formation depth interval is determined as the change in the measured axial flow rate over that interval. This technique is suitable where the flow distribution in the well does not change over the time period when logging is conducted. Additionally, this technique requires the wellbore fluid to be either a hydrocarbon or water, as flow meters typically cannot be used in a corrosive environment, such as when acid is being utilized or acid has been pumped into the wellbore.
During a treatment, such as a stimulation treatment, the flow distribution in a well may change quickly due to either stimulation of the formation layers, which increases the layers' flow capacity, or temporary reduction in the layers' flow capacity as a result of diverting agents. To determine the effectiveness of stimulation or diversion in the well, an substantially instantaneous measurement that gives a “snap shot” of the flow distribution in a well is desired.
One technique for providing an instantaneous measurement is fiber optic Distributed Temperature Sensing (DTS) technology. With an optical fiber in the wellbore, either via a permanent fiber optic line cemented in the casing or placed in an intelligent completion device, or deployed using a coiled tubing or a slickline unit, the optical fiber may measure the temperature distribution along the optical fiber based on optical time-domain reflectometry (OTDR). The advantage of DTS technology or measurements is the ability to acquire in a short time interval the temperature distribution along the well without having to move the tool or toolstring as in traditional well logging, which may be time consuming. DTS effectively gives a snap shot of the temperature profile in the well. DTS has been utilized to measure temperature changes after a stimulation injection, from which the flow distribution can be qualitatively estimated.
The inference of flow distribution is based on the amount of temperature “warm-back” or “cool down” during the shut-in period after injecting a fluid whose temperature is typically different from the formation temperature. For instance, a formation layer that receives a greater fluid flow rate during the injection of a colder fluid warms back more slowly compared to a zone that receives little flow. When the injection fluid is a reactant, the analysis becomes more complicated because the reactant (e.g., acid) may generate heat when in contact with the formation. When the injection fluid is reactant, this may lead to competing temperature responses, with on the one hand cooling due to colder fluid being placed in the warmer formation, and on the other hand heating due to the acid-rock reaction.
While the DTS data collected during shut-in may be analyzed to infer the flow distribution during the preceding injection period, the acquisition time requested for the data to be interpretable may be longer (typically in the order of about two to three hours). In order to utilize the DTS interpretation results to help spot the diverters to achieve optimal flow distribution, the treatment may need to be broken into multiple injection cycles separated by shut-in periods to acquire DTS data to determine the flow evolution, potentially leading to extended job time.
It would be advantageous to be able to interpret the flow distribution from the DTS data during treatment, such as during pumping of the treatment fluid, so that actions can be taken immediately; this would reduce the shut-in periods to the strict minimum, if not avoiding them. A wellbore treatment technique that is utilized is the “bullheading” technique. In performing a bullheading treatment, DTS data may be acquired either using a fiber optic enclosed in a CT (in such a case, there is no flow down the CT pipe, as bullheading occurs in the CT-casing annulus), a slickline dedicated to DTS measurement, or with an optical fiber placed as part of a completion; in some cases, one can also take advantage of any fiber optic permanently placed in the completion to monitor the DTS traces. In those cases, the DTS data during pumping can be analyzed to infer the flow distribution.
It remains desirable to provide improvements in oilfield surface equipment and/or downhole assemblies such as, but not limited to, methods for analyzing and/or interpreting the results of wellbore treatments